Method for testing an engineered geothermal system using one stimulated well

ABSTRACT

Systems and methods for testing a subterranean formation are herein disclosed. According to one embodiment, a method includes stimulating a substantially non-permeable medium within a subterranean formation to create a fractured reservoir. At least one stimulation parameter is measured during stimulation. A well drilled in the subterranean formation is shut-in. A fluid is produced from the subterranean well and at least one production parameter is measured during production. The stimulation and production parameters are used in a numerical reservoir fluid flow model to identify parameters of the fractured reservoir.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority from U.S. provisional application No. 61/087,351, entitled “METHOD FOR TESTING AN ENGINEERED GEOTHERMAL SYSTEM USING ONE SIMULATED WELL,” filed on Aug. 8, 2008 which is incorporated by reference in its entirety, for all purposes, herein.

FIELD OF TECHNOLOGY

The present application is directed to systems and methods for testing subterranean formations. More particularly, the present application is directed to systems and methods for testing engineered geothermal systems.

BACKGROUND

Current testing methods for engineered geothermal systems (EGS) require the drilling of at least two wells in a subterranean formation within which a subterranean reservoir has been created. Testing is conducted over a long time period by injecting fluid into an injection well and producing fluid from a production well. Test data characterizing fluid flow within the subterranean reservoir is compared to results generated by a model to validate the model and predict the long term behavior of the subterranean reservoir. The use of multiple wells and the long data collection periods increase the cost and the risk of current EGS testing methods. In addition, testing results are often limited to quantifying the total pressure drop through the system for a given flow rate.

Currently, single well testing methods are used in the oil and gas, geothermal and water well industries. These industries use a variety of production, injection and tracer methods to characterize the resource. However, the heat exchange area cannot be determined by these methods. Typically, radioactive tracers are utilized to identify flow paths. The concentration of radioactive tracers is measured in the same well or neighboring wells using gamma spectroscopy integrated in a logging tool with a radioactive source. The use of radioactive tracers and radioactive logging tools is expensive and gives rise to health, safety and security concerns. Furthermore, spectral gamma tools are not capable of operation in high temperature environments encountered in geothermal wells.

SUMMARY

Systems and methods for testing a subterranean formation are herein disclosed. According to one embodiment, a method includes stimulating a substantially non-permeable medium within a subterranean formation to create a fractured reservoir. At least one stimulation parameter is measured during stimulation. A well drilled in the subterranean formation is shut-in. A fluid is produced from the subterranean well and at least one production parameter is measured during production. The stimulation and production parameters are used in a numerical reservoir fluid flow model to identify parameters of the fractured reservoir.

The foregoing and other objects, features and advantages of the present disclosure will become more readily apparent from the following detailed description of exemplary embodiments as disclosed herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present application are described, by way of example only, with reference to the attached Figures, wherein:

FIG. 1A illustrates an exemplary system for testing a subterranean formation according to one embodiment;

FIG. 1B illustrates an exemplary system for testing a subterranean formation according to another embodiment; and

FIG. 2 illustrates a flow chart of an exemplary process for testing a subterranean formation.

DETAILED DESCRIPTION

It will be appreciated that for simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the example embodiments described herein. However, it will be understood by those of ordinary skill in the art that the example embodiments described herein may be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the embodiments described herein. It will be understood by those of ordinary skill in the art that the systems and methods herein disclosed may be applied to testing subterranean wells including, but not limited to, geothermal wells, oil wells, gas wells, water wells, injection wells or any other well known in the art for producing or injecting fluids.

FIG. 1A illustrates an exemplary system for testing a subterranean formation 100 according to one embodiment. A subterranean well 102 is drilled in a subterranean formation 100. The subterranean formation 100 includes a substantially non-porous medium having a number of subterranean intervals 104, 106, 108. Treatment fluid is injected into fracture networks 110, 111, 112 within the subterranean intervals 104, 106, 108 to stimulate the fracture networks 110, 111, 112 and create a fractured reservoir 114.

FIG. 1B illustrates an exemplary system for testing a subterranean formation 100 according to another embodiment. The fractured reservoir 114 may be created by isolating subterranean intervals 104, 106, 108 consecutively or simultaneously before stimulating fracture networks 110, 111, 112 therein. The fractured reservoir 114 may be created by blocking fractures 110 in a selected subterranean interval 104 with a blocking agent 120 such as a high viscosity fluid or temporary fracture sealant before stimulating fracture networks 111, 112 in isolated subterranean intervals 106, 108. Selected subterranean intervals 104, 106, 108 may also be isolated with zonal isolation systems such as downhole packers, scab liners or other isolation systems know in the art before stimulating fracture networks 110, 111, 112 therein.

Referring to FIG. 1A and FIG. 1B, the fractured reservoir 114 may be created by injecting any one or a combination of treatment fluids capable of stimulating fractures including, but not limited to water, brine, carbon dioxide, nitrogen, hydrocarbons or any other fluid known in the art that is capable of stimulating fractures in a subterranean formation.

A micro-seismic monitoring system is used to measure parameters within the fractured reservoir 114 as the reservoir is formed. The micro-seismic monitoring system may be any system known in the art for detecting, measuring and processing the seismicity within subterranean formations. The micro-seismic monitoring system may include a seismic data acquisition unit, seismic sensor units and a seismic data line. Seismic sensor units include signal transmitting channels and seismic sensors typically providing two components of horizontal seismic event-sensing and one component of vertical seismic event-sensing during fracture stimulation. The seismic sensor units may be positioned at the surface or in a neighboring wellbore.

Seismic event signals generated by small rock movements along failure planes in the formation 100 are detected by seismic sensors and transmitted to the seismic data acquisition unit via the seismic data line or via a wireless communication network. P and S waves generated by the small rock movements along failure planes are received at seismic sensors at different arrival times. The arrival times of P and S waves are used to determine the location of seismic events and map the propagation of fractures in the fractured reservoir 114 during fracture stimulation. The streaming potential or electromagnetic field generated by the treatment fluid during injection is also detected, measured and processed to determine the flow path and flow characteristics of treatment fluid within the fractured reservoir 114. The polarization of shear seismic waves reflected from stimulated fracture networks 110, 111, 112 may also be detected, measured and processed to determine the portion of the fractured volume within the fractured reservoir 114 that is filled with fluid. Data obtained from the micro-seismic monitoring system is used to generate a micro-seismic event map of seismic events occurring within at least a portion of the subterranean formation 100 including the fractured reservoir 114.

During fracture stimulation, a fiber optic logging tool 130 is used to measure the temperature along the full length of the subterranean well 102 or wellbore and pressure proximate the bottom of the subterranean well 102. The fiber optic logging tool 130 may be any fiber optic logging tool known in the art for measuring temperature and pressure in a downhole environment including, but not limited to those described in U.S. Pat. No. 7,284,903 incorporated herein by reference. The fiber optic logging tool 130 may include an optical source, a fiber optic cable 132, an optical pressure sensor 134 and a fiber optic data acquisition unit 136. The optical source transmits optical signals through the fiber optic cable 132 and the fiber optic data acquisition unit 136 processes and converts signals into temperature and pressure data. The fiber optic cable 132 may be encased in a protective housing or lowered into the subterranean well 102 within a tubing string to protect the fiber optic cable 132 from heat and corrosive fluids within the subterranean well 102. The pressure as a function of time proximate the bottom of subterranean well 102 may be monitored through the optical pressure sensor 134 to control well pressure and prevent tensile fractures from forming in the fractured reservoir 114 during fracture stimulation. The pressure during stimulation is also compared to tests prior to stimulation to determine the improvement in well injectivity obtained from the stimulation. The temperature as a function of time along the vertical and/or horizontal length of the subterranean well 102 is measured to determine the flow path and flow rate of treatment fluid injected into the fractured reservoir 114.

Referring to FIG. 1A, as treatment fluid is injected into the subterranean well 102, fracture networks 110, 111, 112 are stimulated or opened to form fluid flow paths within the fractured reservoir 114. The temperature increases adjacent to the subterranean intervals 104, 106, 108 having stimulated fracture networks 110, 111, 112, because the treatment fluid flows into the stimulated fracture networks 110, 111, 112 and does not circulate within the wellbore to cool the well 102 adjacent to the stimulated intervals 104, 106, 108. The temperature of the subterranean well 102 adjacent to the subterranean intervals 104, 106, 108 is an indication of the location and size of available fluid flow paths and stimulated fracture networks 110, 111, 112 within the subterranean intervals 104, 106, 108.

Referring to FIG. 1B, after an initial stimulation step, a blocking agent 120 may be injected into a subterranean interval 104 to block or plug a stimulated fracture network 110. The blocking agent 120 prevents treatment fluid from entering the stimulated fracture network 110. The circulation of treatment fluid within the wellbore cools the well 102 adjacent to the blocked subterranean interval 104 to a temperature close to the initial temperature of the injected treatment fluid. Treatment fluid injected into the subterranean formation 102 bypasses the blocked subterranean interval 104 and begins stimulating or opening fracture networks 111, 112 within subterranean intervals 106, 108 having higher fracture initiation pressures. The temperature increases adjacent to subterranean intervals 106, 108 having unblocked stimulated fracture networks 111, 112, because the treatment fluid flows into the stimulated fracture networks 111, 112 and does not circulate within the wellbore to cool the well 102 adjacent to the stimulated and unblocked intervals 106, 108. The temperature of the subterranean well 102 adjacent to the subterranean intervals 104, 106, 108 is an indication of the location and size of available fluid flow paths and stimulated fracture networks 110, 111, 112 within the subterranean intervals 104, 106, 108.

Referring to FIG. 1B, a first unique tracer composition may be injected into a first formed fracture network 110 within a selected subterranean interval 104 as part of the treatment fluid during fracture stimulation. The temperature increases adjacent to the subterranean interval 104 wherein new fluid flow paths and a stimulated fracture network 110 are created. The stimulated fracture network 110 within the stimulated subterranean interval 104 may be blocked with a blocking agent 120. A second unique tracer composition may be injected into the subterranean well 102 as part of the treatment fluid to stimulate another fracture network 111 within a subterranean interval 106 having a higher fracture initiation pressure. The temperature increases adjacent to the subterranean interval 106 wherein new fluid flow paths and a stimulated fracture network 111 are created. The stimulated fracture network 111 within the stimulated subterranean interval 106 may be blocked with a blocking agent 120. A third unique tracer composition may be injected into the subterranean well 102 as part of the treatment fluid to stimulate another fracture network 112 within a subterranean interval 108 having a higher fracture initiation pressure. The temperature increases adjacent to the subterranean interval 108 wherein new fluid flow paths and a stimulated fracture network 112 are created. By repeating this process any number of times, a unique tracer composition may be injected into each fracture network 110, 111, 112 in the fractured reservoir 114 by first isolating each subterranean interval 104, 106, 108 consecutively or simultaneously before injecting the unique tracer composition within the selected subterranean interval 104, 106, 108.

Any number of unique tracer compositions may also be injected into each fracture network 110, 111, 112 within a selected subterranean interval 104, 106, 108 as part of a test fluid after simulating fracture networks 110, 111, 112 with the treatment fluid. The test fluid is an aqueous solution including water and a unique tracer composition. A unique tracer composition for each subterranean interval 104, 106, 108 may be injected into each fracture network 110, 111, 112 as part of the test fluid after isolating each subterranean interval 104, 106, 108 consecutively or simultaneously and after stimulating fracture networks 110, 111, 112 with treatment fluid.

The tracer composition is a mixture of reactive tracers and nonreactive tracers having a measurable difference in known thermal or chemical decay kinetics. The reactive tracers may be thermally reactive or chemically reactive. The tracer composition may include one or more reactive tracers and one or more nonreactive tracers. The tracer composition may be injected at a constant ratio of reactive tracers to nonreactive tracers. Nonreactive tracers may also be injected as pulses. The tracer composition may also be injected at equal or unequal ratios of reactive tracers to nonreactive tracers. Tracers may be chemically distinct powders or liquids dissolved in aqueous solution. Reactive and nonreactive tracers may also be injected as part of the treatment fluid or test fluid as entrained vapor or liquid solute.

Chemically reactive tracers react with minerals or other species in the formation 100 and are lost to fluid within the formation 100 during injection, shut-in or flow back. Thermally reactive tracers are thermally unstable and a substantial and measurable portion of thermally reactive tracers is lost due to thermal degradation as the tracer travels through the heated formation 100 during injection, shut-in or flow back. Thermally reactive tracers may have different reaction rates and temperature limitations that affect their rate of degradation and thus their useful life. In an exemplary embodiment, the tracer composition may include low reactive tracers, moderately reactive tracers, highly reactive tracers or combinations thereof. Reactive tracers may include, but are not limited to esters, amines, aryl halides, eosin Y, Oregon Green, rhodamine, sodium fluorescein (uranine), halogenated fluoresceins, and combinations thereof. Sodium fluorescein (uranine), for instance begins to thermally degrade above about 250° C. The thermal decay kinetics (e.g. degradation as a function of time) and chemical decay kinetics (e.g. rate of reaction within the formation) of each injected thermally or chemically reactive tracer is determined before it is injected into the subterranean formation.

Nonreactive tracers are substantially inert and do not thermally degrade and/or do not react with other species in the subterranean formation 100 during injection, shut-in or flow back. Nonreactive tracers may include, but are not limited to alcohols, alkali metals, alkaline-earth metals, halides, sulfonic acid, bromides, rhodamine WT, naphthalene sulfonates, naphthalene disulfonates and sodium fluorescein (uranine). A number of naphthalene sulfonates and naphthalene di-sulfonates are thermally stable at subterranean temperatures below about 340° C.

During injection of the tracer composition the micro-seismic monitoring system is used to measure parameters within the fractured reservoir 114 to generate a micro-seismic event map indicating the extent of the created fractures which may form fluid flow paths within the fractured reservoir 114. The streaming potential of the treatment fluid or the test fluid is detected, measured and processed during injection to determine the movement of fluid, the fluid flow paths and fluid flow characteristics within fracture networks 110, 111, 112. The polarization of shear seismic waves reflected from the stimulated fracture networks 110, 111, 112 may also be detected, measured and processed to determine the volume of fluid filled stimulated fracture networks 110, 111, 112 and the direction of fracture networks 110, 111, 112 within the fractured reservoir 114. The fiber optic logging tool 130 is used to measure parameters such as the temperature of subterranean intervals 104, 106, 108 and the pressure proximate the bottom of the subterranean well 102. The temperature as a function of time along the vertical and/or horizontal length of the subterranean well 102 is measured to determine fluid exit points from the wellbore and fluid flow rates within the fractured reservoir 114. The pressure as a function of time proximate the bottom of subterranean well 102 is monitored to control well pressure and prevent tensile fractures from forming in the fractured reservoir 114 during injection. The flow rate and pressure of treatment fluid or test fluid injected into the subterranean well 102 may also be measured at the surface.

Wellbore image logs obtained prior to the stimulation and/or injection and test data obtained during stimulation and/or injection, including the micro-seismic event map, the pressure within the subterranean well 102 and the temperature along the vertical and/or horizontal length of the subterranean well 102 is used in a stochastic fracture model to generate an equivalent porous medium representing at least a portion of the subterranean formation 100 making up the fractured reservoir 114. The equivalent porous medium is incorporated into a numerical reservoir fluid flow model to simulate the characteristics and expected behavior of at least a portion of the subterranean formation 100 including the fractured reservoir 114.

After injecting the tracer composition as part of the treatment fluid and/or test fluid, the subterranean well 102 is shut-in for a period of time (e.g. hours, days, weeks, months). During shut-in, the tracer composition is permitted to remain in contact with fracture networks 110, 111, 112 in the fractured reservoir 114. During shut-in, the subterranean formation 100 including the fractured reservoir 114 increases in temperature towards the geostatic temperature of the subterranean formation 100. Reactive tracers injected into the fracture networks 110, 111, 112 begin to thermally degrade or chemically react as temperature and time increases. The pressure of the subterranean well 102 may be monitored during shut-in.

After shut-in, the subterranean well 102 is flowed-back to produce the treatment fluid or test fluid having the tracer composition. Once the well is lowing the fiber optic logging tool 130 is lowered back into the subterranean well 102. Temperature along the length of the subterranean well 102 is monitored while pressure is measured downhole. The flow rate of fluid produced from the subterranean well 102 is controlled at a first constant flow rate for a period of time. The draw down or change in pressure and the temperature along the length of the subterranean well 102 is measured at the first constant flow rate. The flow rate of fluid produced from the subterranean well 102 is adjusted to a second constant flow rate for a period of time. The draw down or change in pressure and the temperature along the length of the subterranean well 102 is measured at the second constant flow rate. The flow rate of fluid produced from the subterranean well 102 is adjusted to a third constant flow rate for a period of time. The draw down or change in pressure and the temperature along the length of the subterranean well 102 is measured at the third constant flow rate. The flow rate of fluid produced from the subterranean well 102 may be controlled to produce any number of step flow rate changes in fluid produced from the well 102. The temperature along the length of the subterranean well 102 is measured at each flow rate and the fluid properties at each flow rate are modified according to the temperature and flow rate. The productivity of the subterranean well 102 can be calculated from a plurality of step rate changes in fluid flow rate produced from the well 102.

During flow-back or production, the micro-seismic monitoring system may be used to detect seismicity in the form of the fluid flow noise such as repeated periodic high frequency noise or repeated similar wave form seismic events caused by large pressure drops at fracture nodes. The seismicity can be used to map the propagation of fracture networks 110, 111, 112 within the fractured reservoir 114 during flow-back. The streaming potential or electromagnetic field generated by the treatment fluid during flow-back may also be detected, measured and processed to determine the flow paths and flow characteristics within the fractured reservoir 114. The treatment fluid and/or the test fluid produced from the subterranean well 102 are separated into the liquid phase and the gas phase either in an atmospheric separator or a closed pressure separator. The flow rate of the liquid phase and gas phase of treatment fluid and/or test fluid produced from the subterranean well 102 is measured to determine the fluid enthalpy. Fluorescent spectroscopy is used to measure the concentration of reactive tracers and nonreactive tracers within each unique tracer composition produced from each subterranean interval 104, 106, 108 within the fractured reservoir 114. The concentration of reactive tracers and nonreactive tracers may be measured continuously by running a side stream of the treatment fluid and/or test fluid through a pipeline including an inline spectrometer and/or samples may be taken at regular intervals within the subterranean well 102 or at the surface. The concentration of reactive tracers and nonreactive tracers within each unique tracer composition produced from each subterranean interval 104, 106, 108 indicates the flow contribution and the heat exchange area of each fracture network 110, 111, 112 and each subterranean interval 104, 106, 108 within the fractured reservoir 114.

The area (A) of a planar fracture is determined with the use of Equation 1 and by inputting the concentration of reactive tracers and nonreactive tracers, the temperature (T_(out)) at any time (t) within a planar fracture, the average fluid flow rate (q), the fluid heat capacity (C_(p)), the fluid density (ρ), the fluid heat transfer coefficient (α), and the fluid thermal density (λ) into the numerical reservoir fluid flow model.

T _(out) −T _(i)=(T _(∞) −T _(i))erf[λA/ρC _(p) q(αt)]^(1/2)  1.

Because a unique tracer composition is injected into each fracture network 110, 111, 112, the relative concentrations of each unique reactive tracer and nonreactive tracers in the total fluid flow rate produced from the subterranean well 102 can be used to determine the flow contribution of each fracture network 110, 111, 112 in the fractured reservoir 114. Therefore, by inputting the parameters described above into the numerical reservoir fluid flow model, the heat exchange area (A) of a plurality of fracture networks 110, 111, 112 and the total heat exchange area of the fractured reservoir 114 may be determined.

The test data obtained from testing the subterranean formation 100 during stimulation, injection and flow-back, including but not limited to, the seismicity within the fractured reservoir 114, the pressure proximate the bottom of the subterranean well 102, the temperature adjacent to the subterranean intervals 104, 106, 108, the flow contribution of the fracture networks 104, 106, 108, the flow rate of fluids produced from the well 102, the concentration of reactive and nonreactive tracers produced from the well 102, and the enthalpy of fluids produced from the well 102 is iteratively compared to theoretical data generated by the numerical reservoir fluid flow model to improve the accuracy of the numerical reservoir fluid flow model. The numerical reservoir fluid flow model simulates the expected behavior of at least a portion of the subterranean formation 100 making up the fractured reservoir 114 by predicting the reservoir heat exchange area, reservoir boundary, reservoir circulating volume, reservoir fluid saturation, reservoir permeability, reservoir porosity (storage phi) reservoir skin effect (near wellbore pressure drop), reactive tracer concentration, nonreactive tracer concentration, combined reservoir compressibility and reservoir thickness.

The numerical reservoir fluid flow model may be incorporated in a processor module or a microprocessor run program residing on a computer-readable medium. The numerical reservoir fluid flow model includes an equivalent porous medium representing at least a portion of the subterranean formation 100 including the fractured reservoir 114. The processor module simulates the expected behavior and characteristics of at least a portion of the subterranean formation 100 including the fractured reservoir 114. Test data obtained from testing the subterranean formation 100 during stimulation, injection and flow-back, including but not limited to, the seismicity within the subterranean formation 100, the streaming potential of fluid injected into the subterranean formation 100, the pressure proximate the bottom of the fractured reservoir 114, the temperature adjacent to the subterranean intervals 104, 106, 108, the flow rate of fluid produced from the subterranean intervals 104, 106, 108, the concentration of reactive and nonreactive tracers produced from the subterranean intervals 104, 106, 108, and the enthalpy of fluid produced from the subterranean intervals 104, 106, 108 are input into the processor module. The test data is iteratively compared to the theoretical data generated by the processor module to improve the accuracy of the numerical reservoir fluid flow model. The processor module comprising the numerical reservoir fluid flow model simulates the expected behavior of at least a portion of the subterranean formation 100 including the fractured reservoir 114 by predicting and outputting theoretical data including the reservoir heat exchange area, reservoir boundary, reservoir circulating volume, reservoir fluid saturation, reservoir permeability, reservoir porosity (storage phi), reservoir skin effect (near wellbore pressure drop), reactive tracer concentration, nonreactive tracer concentration, combined reservoir compressibility and reservoir thickness. The processor module comprising the numerical reservoir fluid flow model may also output the theoretical data in terms of the contribution of each subterranean interval within the fractured reservoir.

FIG. 2 illustrates a flow chart of an exemplary process for testing a subterranean formation. A subterranean well is drilled in a subterranean formation. At step 201, treatment fluid is injected into the subterranean formation to stimulate a substantially non-permeable medium within at least a portion of the subterranean formation and to create a fractured reservoir. A tracer composition may be injected into the fractured reservoir as part of the treatment fluid during stimulation at step 201. At step 202, a micro-seismic event map is generated with the use of a micro-seismic monitoring system by measuring parameters including, but not limited to the seismicity within the fractured reservoir, the polarization of shear seismic waves within the fractured reservoir and/or the streaming potential of treatment fluid injected into the fractured reservoir. At step 203, the temperature as a function of time along the vertical and/or horizontal length of the subterranean well and the pressure as a function of time proximate the bottom of the subterranean well is measured with a fiber-optic logging tool during stimulation.

If the tracer composition is injected into the fractured reservoir as part of the treatment fluid during stimulation, the micro-seismic event map of seismic events occurring within the fractured reservoir during stimulation is used to develop an equivalent porous medium representing the fractured reservoir which is incorporated into a numerical reservoir fluid flow model at step 207. If the tracer composition is not injected in the subterranean well as part of the treatment fluid during stimulation, the tracer composition is injected as part of a test fluid at step 204. At step 205, a micro-seismic event map is generated with the use of a micro-seismic monitoring system by measuring parameters including, but not limited to the seismicity within the fractured reservoir, the polarization of shear seismic waves within the fractured reservoir and/or the streaming potential of test fluid injected into the fractured reservoir. At step 206, the temperature as a function of time along the vertical and/or horizontal length of the subterranean well and the pressure as a function of time proximate the bottom of the subterranean well is measured with a fiber-optic logging tool during injection of the test fluid. At step 207, the micro-seismic event map of seismic events occurring within the fractured reservoir during stimulation and/or injection of the test fluid is used to develop an equivalent porous medium representing the fractured reservoir which is incorporated into the numerical reservoir fluid flow model.

At step 208 the subterranean well is shut-in. The pressure of the subterranean well may be monitored during shut-in. After shut-in, the subterranean well is flowed-back and fluids within the fractured reservoir are produced at step 209. After the well starts flowing, the fiber-optic logging tool is lowered into the subterranean well at step 210 to measure the temperature as a function of time along the vertical and/or horizontal length of the well and the pressure as a function of time proximate the bottom of the well. At step 211 the flow rate of fluid produced from the subterranean well is measured and the concentration of reactive tracers and nonreactive tracers is measured with a fluorescent spectrometer. At step 212, test data obtained from testing the subterranean formation during stimulation, injection and flow-back, including but not limited to, the seismicity within the fractured reservoir, the pressure proximate the bottom of the subterranean well, the temperature along the vertical and/or horizontal length of the well, the flow contribution of a plurality of fracture networks within the fractured reservoir, the flow rate of fluids produced from the well, the concentration of reactive and nonreactive tracers produced from the well, and the enthalpy of fluids produced from the well is iteratively compared to theoretical data generated as output from the numerical reservoir fluid flow model.

Example embodiments have been described hereinabove regarding improved systems and methods for testing a subterranean formation. Various modifications to and departures from the disclosed example embodiments will occur to those having ordinary skill in the art. The subject matter that is intended to be within the spirit of this disclosure is set forth in the following claims. 

1. A method comprising: stimulating a substantially non-permeable medium within a subterranean formation to create a fractured reservoir; measuring at least one stimulation parameter during stimulation; using the stimulation parameter in a numerical reservoir fluid flow model; shutting-in a subterranean well drilled in the subterranean formation; producing a fluid comprising at least a treatment fluid from the subterranean well; measuring at least one production parameter during production; using the production parameter in the numerical reservoir fluid flow model; and identifying a heat exchange area of the fractured reservoir using the numerical reservoir fluid flow model.
 2. The method as recited in claim 1, wherein stimulating a substantially non-permeable medium within the subterranean formation comprises injecting the treatment fluid into the subterranean formation.
 3. The method as recited in claim 2, wherein measuring at least one stimulation parameter during stimulation comprises measuring at least one parameter from a group consisting of: seismicity within the subterranean formation, streaming potential of the treatment fluid injected into the subterranean formation, temperature within the subterranean well and pressure within the subterranean well.
 4. The method as recited in claim 2, wherein the treatment fluid comprises a tracer composition.
 5. The method as recited in claim 4, wherein the tracer composition comprises at least one reactive tracer and at least one nonreactive tracer.
 6. The method as recited in claim 5, wherein measuring at least one production parameter during production comprises measuring at least one parameter from a group consisting of: flow rate of the fluid produced from the subterranean well, concentration of the at least one reactive tracer, concentration of the at least one nonreactive tracer, temperature within the subterranean well, and pressure within the subterranean well.
 7. The method as recited in claim 2, further comprising injecting a test fluid into the subterranean formation.
 8. The method as recited in claim 7, wherein measuring at least one stimulation parameter during stimulation comprises measuring at least one parameter from a group consisting of: seismicity within the subterranean formation, streaming potential of the treatment fluid injected into the subterranean formation, temperature within the subterranean well and pressure within the subterranean well.
 9. The method as recited in claim 8, further comprising measuring at least one injection parameter during injection.
 10. The method as recited in claim 9, wherein measuring at least one injection parameter during injection comprises measuring at least one parameter from a group consisting of: seismicity within the subterranean formation, streaming potential of the test fluid injected into the subterranean formation, temperature within the subterranean well and pressure within the subterranean well.
 11. The method as recited in claim 10, wherein the test fluid comprises a tracer composition.
 12. The method as recited in claim 11, wherein the tracer composition comprises at least one reactive tracer and at least one nonreactive tracer.
 13. The method as recited in claim 12, wherein producing a fluid further comprises producing a fluid comprising at least the test fluid from the subterranean well.
 14. The method as recited in claim 13, wherein measuring at least one production parameter during production comprises measuring at least one parameter from a group consisting of: flow rate of the fluid produced from the subterranean well, concentration of the at least one reactive tracer, concentration of the at least one nonreactive tracer, temperature within the subterranean well, and pressure within the subterranean well.
 15. A computer program product comprising: at least one computer-readable medium; at least one processor module residing on the computer-readable medium and operative to: use an input of test data obtained from testing a subterranean formation in a numerical reservoir fluid flow model; and provide an output of theoretical data generated by the numerical reservoir fluid flow model.
 16. The computer program product as recited in claim 15, wherein the subterranean formation comprises at least one subterranean interval.
 17. The computer program product as recited in claim 16, wherein the subterranean formation is stimulated by injecting treatment fluid into the at least one subterranean interval to create a fractured reservoir.
 18. The computer program product as recited in claim 17, wherein the treatment fluid comprises a tracer composition comprising at least one reactive tracer and at least one nonreactive tracer.
 19. The computer program product as recited in claim 18, wherein the input of test data obtained from testing the subterranean formation comprises at least one parameter from a group consisting of: seismicity within the subterranean formation, streaming potential of the treatment fluid injected into the at least one subterranean interval, temperature adjacent to the at least one subterranean interval, pressure proximate the bottom of the fractured reservoir, flow rate of the treatment fluid produced from the at least one subterranean interval, concentration of the at least one reactive tracer, concentration of the at least one nonreactive tracer.
 20. The computer program product as recited in claim 19, wherein the output of theoretical data venerated by the numerical reservoir fluid flow model comprises at least one parameter from a group consisting of: heat exchange area of the at least one subterranean interval, circulating volume of the treatment fluid within the at least one subterranean interval, permeability of the at least one subterranean interval, porosity of the at least one subterranean interval, combined compressibility of the at least one subterranean interval and thickness of the at least one subterranean interval. 